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Results
Abstract Historically a number of large offshore fields in the Arabian Gulf have adopted a ‘hub and spoke’ type development concept, comprising of a number of remote Well-Head Platforms (WHPs) connected to a central processing complex via individual subsea pipelines. As these types of fields become more mature Enhanced Oil Recovery (EOR) Techniques may be required to maintain or enhance oil production rates. The addition of subsea and topside infrastructure becomes increasingly difficult to accommodate due to major legacy issues such as ‘hub and spoke’ type developments, with the associated significant subsea congestion that arises through individual pipeline tie-backs. This paper presents a case study for a planned EOR development of an existing offshore field in circa 50m water depth located in the North Arabian Gulf. The existing facilities have been developed over several phases in a ‘hub and spoke’ manner over the past 50 years and hence are highly congested, especially around the central processing complex. Furthermore, the production fluids are highly corrosive due to the presence of CO2, H2S and high-salinity (produced) water. The EOR development requires extensive additional infrastructure, comprising of over 200 additional wells distributed over a number of existing remote WHPs, in order to maintain current oil production rates. The paper describes how the numerous issues and risks associated with this development were resolved via the adoption of a holistic assessment approach considering the full project life-cycle. Due to the interdependency of the problem a multi-disciplinary approach, leveraging process and facilities, subsea and pipelines, and materials technology expertise, was essential in order to optimise the field layout and overall development concept. The selected concept deviates from the traditional ‘hub and spoke’ type approach and instead takes the form of two off central-spine large diameter trunk-lines connected to numerous smaller diameter spur-lines. The trunk-lines are manufactured from Carbon Steel (CS) linepipe with internal corrosion managed via a continuous supply of Corrosion Inhibitor (CI) delivered by a small-diameter supply-line piggy-backed to the trunk-line. The spur-lines are manufactured from Corrosion Resistant Alloy (CRA) clad linepipe, thereby negating the requirement for continuous corrosion inhibition. Future tie-in flexibility is provided by additional subsea tees and subsea double block and bleed valves pre-installed on the trunk-lines. The paper demonstrates that effective discipline integration enables a holistic review of competing solutions to be undertaken. This approach resulted in a number of value opportunities being realized on the project: Simple and robust production system. Straightforward pipeline installation campaign with flexibility for phased installation if required. Minimal number (and complexity) of pipeline crossings. Reliable and low lifecycle cost pipeline system with a reduced operations and maintenance requirements. Minimal extent of brownfield modifications. Provided fluid gathering flexibility for future drilling / reservoir development.
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)
Abstract Sealing technologies provide a vital role in a wide range of applications no more so than in the design and development of Retrievable Bridge Plugs (RBP) where performance is a vital safety and operational consideration. Moreover, for workover operations using RBPs it is also essential that deployment and recovery are equally as reliable as the pressure and temperature performance of the plug. Traditional retrievable bridge plugs based on solid elastomeric seals have been the mainstay of well intervention since the 1940’s. However, the long-term shift towards gas production, higher pressures, higher temperatures and increased regulatory standards means these systems can no longer provide the performance the industry demands. New innovative technologies are needed to bridge this gap and this paper provides evidence of once such technology with the potential to service the next era of exploration and production. The paper explores some of the operational and practical limitations of traditional solid elastomer sealing technology for RBPs and introduces a new type of hybrid metal-polymer seal offering significantly improved sealing performance, larger running clearances and enhanced reliability. The new seal technology is described alongside experimental data on the seal’s performance and operational configuration.
Abstract Asphaltenes are the most polar component of crude oils and lead to problems such as well-bore and pipeline clogging during extraction and transportation of crude oil. Previous works have successfully used ionic and nonionic surfactants to delay and prevent asphaltene precipitation. It has also been shown that water in pipelines, delays deposition. In this work, the effect of combining water and brine with ionic and nonionic surfactants are investigated in two Middle Eastern crude oils. Results indicate that water and brine do not change the amount of asphaltenes precipitated. The dispersing action of a nonionic surfactant BA, which acts on a colloidal scale to lower aggregate size and truncate asphaltene growth, is not altered by water / brine. The addition of an ionic surfactant, dodecylbenzene sulphonic acid, which molecularly solubilizes the asphaltenes via electrostatic interactions, acts antagonistically when water / brine is present, and destabilizes the crude oil. The above effects are attributed to changes in the electrostatic interactions between the surfactant and the asphaltenes, in the presence of water / brine.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.72)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract Pipeline integrity is a challenge for Oil Companies since number, length and age of pipelines is increasing worldwide, and people are increasingly aware about environmental protection. A project aimed at a safer and continuous service of such components is underway in eni, with attention to implement innovative technologies. The objective of this paper is to describe how PIM (Pipeline Integrity Management) project can be effective towards a safer pipeline management. The engineering and the operation team are activated To establish a pipeline integrity strategy To define an inspection strategy issuing an Inspection & Maintenance Plan To execute a Baseline Inspection as a benchmark to future inspection strategy To implement a Data Management System for pipelines in service. Programmed inspection are performed and the pipeline integrity is evaluated. A proper requalification/life extension process is started if: Operating conditions do require special care Design life is exceeded Data are collected and analysed, hazard are identified and criticalities examined. Inspection plans are specified and implemented to maintain pipeline integrity and to prevent failures. A growing data base is implemented, containing all kind of data about production lines transporting different classes of fluids, as for instance construction data, geometry, materials characterization and so on; the data base is implemented with information about active damage mechanisms, inspection results, failure analysis, production and fluid characteristics, flow dynamic modelled with numerical codes and more. The number of in inline inspection (ILI) reports implemented is growing. Unfortunately, not all portions of a pipeline – especially when quite old - can be inspected, due to geometrical constraints; this is why part of the effort is directed towards innovation and studies, as for instance: To obtain a better understanding of damage evolution To model the thickness loss of the components To apply innovative techniques for inspection. Collected data allow to perform a sensible engineering risk analysis, and to better plan further inspection activities. Examples of cases will be discussed in the paper and the decision tree for selected situations will be presented. The paper will show how data records are important and how an integrated approach to inspection and maintenance can be beneficial to the Oil & Gas Business. An integrated approach between Engineering and Operation allow to develop "integrity friendly" solutions, implementing existing inspection and maintenance plans.
- Africa > Middle East (0.46)
- Asia > Middle East (0.28)
- Europe (0.28)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Management > Risk Management and Decision-Making (1.00)
- (4 more...)
In-Line Measurement of H2S Content in Flow with a Multiphase Flow Meter - Case Study in a Giant Field under Sour Gas Re-Injection
Lindsell, K.. (Tengizchevroil) | Wang, S. W. (Tengizchevroil) | Clarke, J.. (Tengizchevroil) | Jambayev, A.. (Tengizchevroil) | Ricquebourg, J.. (Schlumberger) | Kaipov, Y.. (Schlumberger) | Zakharov, L.. (Schlumberger) | Hollaender, F.. (Schlumberger)
Abstract A new approach in advanced multiphase metering methodology designed for use in sour fields, quantifying H2S content in flow and properly accounting for it in the different phase rate measurements is presented. Flow metering in sour fields is challenging due to the need for containment of produced fluids and the effect of fluid properties in the interpretation of the measurements. The addition of H2S measurement provides additional information for production and reservoir monitoring and also yields improvements in flow metering, accounting for variations in fluid properties used for multi-phase calculation. Multiphase Flow Meters (MPFM) utilizing multi-energy gamma-ray fraction measurements are based on the ability of oil, gas, and water to absorb gamma rays of two different wavelengths. Adding an extra measurement at a third level of energy and leveraging the large contrast between the attenuation of sulfur and that of hydrocarbon and water components makes it possible to determine the mass fraction of H2S as an additional output. This technique was applied in Tengiz field, Kazakhstan, characterized by a high H2S content. In order to maintain reservoir pressure, improve recovery and utilize produced associated gas, a sour gas miscible flood pilot was started in 2007. The monitoring of compositional variation in producers is critical in the understanding of solvent (sour gas) distribution and thus in managing production-injection patterns to optimize plant throughput. Early field trials of the method were made comparing metered H2S content with surface PVT samples, confirming the accuracy of the methodology. The technology was then implemented systematically but strategically across the field. The in-line H2S measurement with automatic updates for variation in fluid properties was applied in two distinct areas: within the sour gas injection pilot area, where solvent levels vary, and outside the area where hydrocarbon composition is known to be homogeneous and constant. Long and short term tests with multi-rate well tests were conducted. Full datasets were collected from the MPFM to evaluate measurement stability and representativity under different flowing conditions and compared to results obtained without accounting for compositional changes. The results show a stable, accurate and continuous measurement of H2S content in produced fluid and an enhanced measurements of water, oil and gas rates comparable with PVT results. The in-line H2S measurement based on multi-energy gamma ray measurements is the only continuous H2S measurement technology available in multiphase flow conditions. It can be retrofitted to existing MPFMs, allowing to get additional parameter and enhanced stability of flow rate measurements where properties of produced fluid vary continuously. This paper will begin with a presentation of the theory, formulation and validation of the in-line H2S measurement and then go on to present a case history of the application in the Tengiz field, Kazakhstan for Tengizchevroil (TCO).
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Tengiz Formation (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Korolev Formation (0.99)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Downhole and wellsite flow metering (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
Abstract Water flooding using seawater is a major oil filed operation implemented in different carbonate and sandstone reservoirs to maintain reservoir pressure and enhance oil recovery. However, due to the high sulfate content in the injected seawater, significant calcium, barium and strontium sulfate scale deposition can occur and cause severe formation damage. Typically, scale inhibitors are applied in the field to prevent the formation of calcium sulfate scale where they act either as chelating agents to form a soluble complex, as threshold inhibitors, which block the development of the supercritical nuclei or as retarders of the growth of the calcium sulfate crystals. The objective of this study is to evaluate the effectiveness of different types of scale inhibitors to prevent the formation of calcium sulfate scale during the injection of seawater into high-salinity bearing carbonate reservoirs. Jar testing and SoftPitzer software were used to investigate the calcium sulfate precipitation due to the mixing of high calcium-content (37,000 mg/L) formation water and high sulfate-content (4,000 mg/L) seawater. This investigation was conducted on different mixtures of formation water and seawater at reservoir temperature of 155°F. Different types of scale inhibitors were tested to prevent the scaling of calcium sulfate in mixtures of seawater and formation water. The compatibility of these scale inhibitors with calcium ions present in formation water and also their effectiveness in preventing CaSO4 scaling were investigated using bottle testing. In addition, coreflood experiments were conducted to determine the adsorption behavior of these inhibitors in carbonate rocks. Results showed that the application of two scale inhibitors (Acrylic homopolymer-based) can successfully mitigate calcium sulfate scale formation in seawater/formation water mixtures up to 155°F. Each one of these two scale inhibitors has its own effective minimum inhibition concentration (MIC). In addition to these results, the paper provides insights into the adsorption behavior of these inhibitors in carbonate rocks and how this affects their performance.
- North America > United States (0.47)
- Asia > Middle East (0.46)
- Geology > Mineral > Sulfate (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.55)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Geology > Mineral > Silicate > Phyllosilicate (0.46)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Objectives/Scope To reduce flaring of produced hydrocarbon during well testing operations in order to protect the environment, comply with safety regulations and conserve oil. Methods, Procedures, Process During well-testing operations the produced hydrocarbon is usually flared in the open flare pit. As per the existing company's HSE procedures, flaring during well testing is considered as a safe option. However, flaring activities needs to be minimized or eliminated as some wells are located in environmentally sensitive areas which are close to farms, Highways or camping area. Due to location constraints the flaring should be minimized to the possible extent. As the well is exploratory, the well was not connected yet to the production facility. The only means of oil transportation will be by using road tankers, for that the H2S concentration in oil needs to be reduced to a permissible limit. The heavy oil well to be tested contains H2S concentration upto 22 %(220,000 ppm) in gas. A novel process was initiated to eliminate/minimize flaring during well testing operations. H2S scavenger technology was selected for field trial to convert the produced sour liquid to be suitable for transportation through vacuum tankers to the nearest production facility. Accordingly H2S scavenger chemical was arranged and well test surface layout was modified with additional chemical dosing points. After separating the gas from oil using surge tank and separator dosed H2S Scavenger into oil line. This exercise resulted in ensuring that the H2S concentration in treated oil is at a permissible limit and the oil is suitable to be transported using road tankers. Results, Observations, Conclusions Field trail was implemented in sour heavy oil well to evaluate the feasibility of using H2S scavenger chemical to mitigate/minimize high H2S concentration in the produced fluid. Two heavy oil wells (17-20 API) were tested with this process and H2S content in oil was reduced to almost 15 ppm. Achieved economical H2S scavenger treatment cost of $18/bbl for reducing H2S in oil from 600 ppm to 15 ppm. Oil flaring was eliminated and only small quantity of the produced sour gas(0.001mmscfd) was flared safely through flare stack. Approximately 5,500 bbls of crude oil were produced from an exploratory well and safely transported by road tankers to nearby production facility during two weeks of testing period. For the first time in Kuwait an exploratory sour heavy oil well was successfully tested without flaring oil. Novel/Additional Information The innovative solution of using H2S Scavenger during testing the sour well had eliminated flaring of crude oil which avoided environmental pollution and conserved the produced oil. This success proves that sour heavy oil wells can be tested safely without flaring oil and paves the way for implementing this novel concept in future applications.
- Asia > Middle East > Kuwait (0.37)
- North America > United States > Wyoming > Sweetwater County (0.24)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
Abstract Organic amines are corrosion control agents that increase pH and scavenge corrosive contaminants. Their presence in sour water can lead to the formation of heat-stable salts, resulting in potentially corrosive deposits. The measurement and monitoring of amines in sour water requires chromatographic techniques, with corresponding complexity, training, and expense. A rapid, field-deployable method to measure amines in refinery process waters would speed testing time, increase the temporal data resolution, and allow for immediate response and process adjustment. We present a new approach to amine measurement using Surface-Enhanced Raman Spectroscopy. By mixing a pH-adjusted sample with gold nanoparticles, a strong amine signal is obtained with a potential for sub-100-ppb detection. An optimized approach for ppm-level detection reports 27.8±3.9-ppm and 76.4±5.1-ppm for ~25-ppm and ~75-ppm samples, respectively, with more than one-hundred tests per sample over a three-month period. This method is at least as accurate, sensitive, and repeatable as ion chromatography, yet can be performed in the field in under five minutes.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Downstream (1.00)
ABSTRACT It is widely known that pressure drop and compositional change of reservoir fluid causes asphaltene precipitation. Regarding compositional change, gas injection is believed to be a typical trigger of asphaltene deposition. The injected gases are mixed with reservoir fluid and gradually change the composition in the reservoir as gas front is heading. For such fluids, compositional changes are believed to take place not only near gas injectors but also in a wider area. Thus, asphaltene precipitation risks should be considered on field scale. This paper demonstrates how to generate "Asphaltene Risk Map on field scale" based on the correlation between Asphaltene Onset Pressure (AOP) and fluid composition. A Middle Eastern offshore oil field which encounters asphaltene problems was selected as an example because the above two key parameters are mainly working in the field for destabilizing asphaltene. For creating risk map, compositions of reservoir fluid near the asphaltene problem wells were calculated from reservoir simulation. The calculated compositions were applied for the asphaltene model with calibrating measured AOP. Various combinations were evaluated on the plots of AOP versus composition to find well-converged correlation. Eventually, the C1-C19 component was selected to achieve the most reasonable correlation to AOP for this case. According to pressure variation from the correlated AOP, risk ratings were proportionally distributed on the plot. Based on these risk ratings, "Asphaltene Risk Map" was translated from the relationship between C1-C19 component and pressure. The created risk map shows a reasonable tendency to replicate the timing of actual asphaltene precipitation. In addition, two types of asphaltene precipitation mechanism were confirmed on the Risk Map. Namely, higher risk was estimated in two producers; one is located in the gas breakthrough area due to gas cap expansion, and the other is isolated from the gas breakthrough area but is in the vicinity of free gas observed area where compositional change occurs. This Asphaltene Risk Map is considered useful to optimize gas injection plan, in particular. Time-lapse prediction of asphaltene risk can suggest timing and/or priority to prepare mitigation plan.
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract Several wells in a carbonate reservoir have experienced significant reduction in their oil productivity. Bailer samples collected from these wells showed that they were damaged with organic/inorganic deposition. Analysis of the collected material showed that the organic deposits consisted of asphaltene and associated paraffins while the inorganic deposits were mainly calcite with ankerite, anhydrite and small amounts of quartz and halite. The formation of calcium carbonate scale is anticipated to occur due to CO2 degassing during production. In addition, these wells produce commingled oil from two carbonate reservoirs which allow their formation waters to mix together; therefore, scaling tendency prediction showed a positive saturation index for calcium carbonate. The sulfate scale in the form of anhydrite is anticipated to be formed due to mixing of high sulfate source (seawater), used to maintain reservoir pressure, with a calcium rich source (formation water). The colloidal instability index from SARA analysis indicated that the reservoir oil in this field has a moderate instability to potentially precipitate asphaltenes. Additionally, the interaction of low pH scale inhibitor with the formation oil and presence of charged particles such as calcite will destabilize asphaltenes in oil. Two techniques were examined toward dissolving the organic/inorganic deposition including a two-stage and a single-stage method. The two-stage method involves the use of solvent preflush to remove the organic coating material from the whole deposits followed with the use of HCl acid to remove the remaining inorganic deposits. An emulsified HCl acid/solvent is used in the single stage method to remove the whole deposits. The paper discusses different analytical techniques used to identify the nature of the damaging material, mechanism of organic/inorganic deposition, and the optimization of dissolver/solvent systems to remove formation damage and restore productivity of damaged wells. It also assesses and optimizes the current used scale inhibitor squeeze (SIS) treatment program.
- Asia > Middle East (0.94)
- North America > United States > Texas (0.68)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)